Oil and Natural Gas Sector Compressors

Report for Oil and Natural Gas Sector Compressors

Review Panel

April 2014

Prepared by

U.S. EPA Office of Air Quality Planning and Standards (OAQPS)

This information is distributed solely for the purpose of pre-dissemination peer review under

applicable information quality guidelines. It has not been formally disseminated by EPA. It does not

represent and should not be construed to represent any Agency determination or policy.
ii
iii

Table of Contents

PREFACE 1

1.0 INTRODUCTION 2

2.0 PROCESS DESCRIPTIONS 4

2.1 Reciprocating Compressors ...........................................................................................................................4

2.2 Centrifugal Compressors................................................................................................................................5

3.0 EMISSIONS DATA AND EMISSIONS ESTIMATES 7

3.1 GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks 

(GRI/EPA, 1996a) ...........................................................................................................................................8

3.2 Natural Gas Industry Methane Emission Factor Improvement Study, Final Report (URS/UT, 2011) 13

3.3 Greenhouse Gas Reporting Program (U.S. EPA, 2013).............................................................................15

3.4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)..........................18

3.5 Development of the New Source Performance Standard (NSPS) For Oil and Natural Gas Production 

(U.S. EPA, 2011b and U.S. EPA, 2012a) .....................................................................................................21

3.6 Characterizing Pivotal Methane Emissions from the Oil and Natural Gas Sector, (API /ANGA, 2012)

24

3.7 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and 

Natural Gas Industries (ICF International, 2014)......................................................................................25

3.7.1 ICF 2011 Baseline .................................................................................................................................25

3.7.2 ICF Projections to 2018 .........................................................................................................................28

4.0 AVAILABLE COMPRESSOR EMISSIONS MITIGATION TECHNIQUES 29

4.1 Reciprocating Compressor - Rod Packing Replacement...........................................................................29

4.1.1 Description.............................................................................................................................................29

4.1.2 Effectiveness..........................................................................................................................................30

4.1.3 Cost of Controls.....................................................................................................................................32

4.2 Reciprocating Compressor – Gas Recovery ...............................................................................................34

4.2.1 Description.............................................................................................................................................34

4.2.2 Effectiveness..........................................................................................................................................35
iv

4.2.3 Cost of Controls.....................................................................................................................................35

4.3 Centrifugal Compressor - Dry Seals............................................................................................................36

4.3.1 Description.............................................................................................................................................36

4.3.2 Effectiveness..........................................................................................................................................37

4.3.3 Cost of Controls.....................................................................................................................................38

4.4 Centrifugal Compressor - Wet Seal with a Flare .......................................................................................39

4.4.1 Description.............................................................................................................................................39

4.4.2 Effectiveness..........................................................................................................................................39

4.4.3 Cost of Controls.....................................................................................................................................40

4.5 Centrifugal Compressor - Wet Seals with Gas Recovery for Use .............................................................40

4.5.1 Description.............................................................................................................................................40

4.5.2 Effectiveness..........................................................................................................................................41

4.5.3 Cost of Controls.....................................................................................................................................41

5.0 SUMMARY 42

6.0 CHARGE QUESTIONS FOR REVIEWERS 43

7.0 REFERENCES 45
1

PREFACE

On March 28, 2014 the Obama Administration released a key element called for in the 

President’s Climate Action Plan: a Strategy to Reduce Methane Emissions. The strategy 

summarizes the sources of methane emissions, commits to new steps to cut emissions of this 

potent greenhouse gas, and outlines the Administration’s efforts to improve the measurement of 

these emissions. The strategy builds on progress to date and takes steps to further cut methane 

emissions from several sectors, including the oil and natural gas sector. 

This technical white paper is one of those steps. The paper, along with four others, 

focuses on potentially significant sources of methane and volatile organic compounds (VOCs) in 

the oil and gas sector, covering emissions and mitigation techniques for both pollutants. The 

Agency is seeking input from independent experts, along with data and technical information 

from the public. The EPA will use these technical documents to solidify our understanding of 

these potentially significant sources, which will allow us to fully evaluate the range of options 

for cost-effectively cutting VOC and methane waste and emissions.

The white papers are available at: 

www.epa.gov/airquality/oilandgas/whitepapers.html
2

1.0 INTRODUCTION

The oil and natural gas exploration and production industry in the U.S. is highly dynamic 

and growing rapidly. Consequently, the number of wells in service and the potential for greater 

air emissions from oil and natural gas sources is also growing. There were an estimated 504,000

producing gas wells in the U.S. in 2011 (U.S. EIA, 2012a), and an estimated 536,000 producing 

oil wells in the U.S. in 2011 (U.S. EIA, 2012b). It is anticipated that the number of gas and oil 

wells will continue to increase substantially in the future because of the continued and expanding 

use of horizontal drilling combined with hydraulic fracturing (referred to here as simply 

hydraulic fracturing).

Due to the growth of this sector and the potential for increased air emissions, it is 

important that the U.S. Environmental Protection Agency (EPA) obtain a clear and accurate

understanding of emerging data on air emissions and available mitigation options. This paper 

presents the Agency’s understanding of emissions and available control technologies from a 

potentially significant source of emissions in the oil and natural gas sector.

Oil and gas production from unconventional formations such as shale deposits or plays 

has grown rapidly over the last decade. Oil and natural gas production is projected to steadily 

increase over the next two decades. Specifically, natural gas development is expected to increase 

by 44% from 2011 through 2040 and crude oil and natural gas liquids are projected to increase 

by approximately 25% through 2019 (U.S. EIA, 2013). The projected growth is primarily led by 

the increased development of shale gas, tight gas, and coalbed methane resources utilizing new 

production technology and techniques such as horizontal drilling and hydraulic fracturing.

According to the U.S. Energy Information Administration (EIA), over half of new oil wells 

drilled co-produce natural gas (U.S. EIA, 2013). Based on this increased oil and gas development 

and the fact that half of these new oil wells co-produce natural gas, the potential exists for 

increased emissions from production through distribution of natural gas from these operations.

Compressors have been identified as an emission source that has the potential to produce 

emissions to the atmosphere during oil and gas production (gathering and boosting), processing, 
3

transmission and storage. Compressors are mechanical devices that increase the pressure of 

natural gas and allow the natural gas to be transported from the production site, through the 

supply chain, and to the consumer. Vented emissions from compressors occur from seals (wet 

seal compressors) or packing surrounding the mechanical compression components

(reciprocating compressors) of the compressor. These emissions typically increase over time as 

the compressor components begin to degrade. Leak emissions from various compressor 

components can also occur, but those emissions are not covered in this paper because the causes 

and mitigation techniques are different than the vented emissions.

The purpose of this paper is to summarize the EPA’s understanding of vented VOC and 

methane emissions from compressors, and the EPA’s understanding of available mitigation 

techniques (practices and equipment) to reduce vented emissions from compressors. Included in 

the mitigation techniques discussion is our understanding of the efficacy and cost of these

technologies and the prevalence of use of the technologies in the industry.

In the oil and natural gas sector, the most prevalent types of compressors used are 

reciprocating and centrifugal compressors. For the purposes of this paper, a reciprocating

compressor is defined as:

A piece of equipment that increases the pressure of a process gas by positive 

displacement, employing linear movement of the driveshaft.

For the purposes of this paper, a centrifugal compressor is defined as:

Any machine for raising the pressure of a natural gas by drawing in low pressure natural 

gas and discharging significantly higher pressure natural gas by means of mechanical 

rotating vanes or impellers. 

Compressors are used in all aspects of natural gas development. In the production 

segment, compressors are used at the wellhead to compress gas for fluids removal and pressure 

equalization with gathering equipment systems. However, the primary use of compressors is in 
4

the natural gas processing, transmission and storage (particularly underground storage) segments 

of the industry. 

Section 2 of this document provides background and context for discussions of vented 

emissions from compressors, Section 3 presents our understanding of vented VOC and methane 

emissions from compressors, and Section 4 provides our understanding of available emissions 

mitigation techniques. Section 5 summarizes the EPA’s understanding based on the information 

presented in Sections 3 and 4, and Section 6 presents a list of charge questions for reviewers to 

assist us with obtaining a more comprehensive understanding of vented VOC and methane 

emissions from compressors and emission mitigation techniques.

2.0 PROCESS DESCRIPTIONS 

2.1 Reciprocating Compressors 

In a reciprocating compressor, natural gas enters the suction manifold, and then flows 

into a compression cylinder where it is compressed by a piston driven in a reciprocating motion 

by the crankshaft powered by an internal combustion engine. For the purposes of this paper,

reciprocating compressor rod packing is defined to mean:

A series of flexible rings in machined metal cups that fit around the reciprocating 

compressor piston rod to create a seal limiting the amount of compressed natural gas that 

escapes to the atmosphere.

Over the operating life of the compressor, the rings become worn and the packing system 

will begin to wear resulting in higher leak rates. Emissions from packing systems originate from 

mainly four components; the nose gasket, between the packing cups, around the rings and 

between the rings and the shaft. See Figure 2-1 for a depiction of a typical compressor rod 

packing system configuration. Typically, gases leaked from the packing system are vented.
5

Figure 2-1. Typical Reciprocating Compressor Rod Packing System

(U.S. EPA, 2006a)

2.2 Centrifugal Compressors

Centrifugal compressors use a rotating disk or impeller to increase the velocity of the gas 

where it is directed to a divergent duct section that converts the velocity energy to pressure 

energy. These compressors are primarily used for continuous, stationary transport of natural gas 

and are widely used in the processing and transmission industry segments. Centrifugal 

compressors are equipped with either a wet or dry seal configuration. Wet seals use oil around 

the rotating shaft to prevent natural gas from escaping where the compressor shaft exits the 

compressor casing. The oil is circulated at high pressure to form a barrier against compressed 

natural gas leakage. The circulated oil entrains and absorbs some compressed natural gas that

may be released to the atmosphere during the seal oil recirculation process (degassing or offgassing). Figure 2-2 illustrates the wet seal compressor configuration.
6

Figure 2-2. Typical Centrifugal Compressor Wet Seal (U.S. EPA, 2006b)

Alternatively, dry seal compressors use the opposing force created by hydrodynamic 

grooves and springs to provide a seal. The opposing forces create a thin gap of high pressure gas 

between the rings through which little gas can leak. The rings do not wear or need lubrication 

because they are not in contact with each other. The combination of two or more of the dry seals 

in series is called “tandem dry seals” and is effective in reducing gas leakage. Figure 2-3

illustrates the tandem dry seal compressor configuration. 

Gas emissions from wet seal centrifugal compressors have been found to be higher than 

dry seals compressors primarily due to the off-gassing of the entrained gas from the oil. This gas 

is not suitable for sale and is either released to the atmosphere, flared, or routed back to a 

process. In addition to lower gas leakage (and therefore lower emissions), dry seals have been 

found to have lower operation and maintenance costs than wet seal compressors because they are 

a mechanically simpler design, require less power to operate, are more reliable and require less 

maintenance. Dry seal compressors will be discussed in more detail in Section 4.
7

Figure 2-3. Typical Centrifugal Compressor Tandem Dry Seal (U.S. EPA, 2006b)

3.0 EMISSIONS DATA AND EMISSIONS ESTIMATES 

There are several sources of emissions factors, activity data, and direct measurement data

that have been used to estimate emissions from compressors in the oil and natural gas sector.

Some of these studies are listed in Table 3-1, along with an indication of the type of information 

contained in the study (i.e., activity level and emissions data).
8

Table 3-1. Summary of Major Sources of Information and Data on Compressors

Name Affiliation

Year of 

Report

Activity 

Factor

Emissions 

Data

Methane Emissions from the Natural 

Gas Industry: Equipment Leaks 

(GRI/U.S. EPA, 1996)

Gas Research 

Institute (GRI)/ U.S. 

Environmental 

Protection Industry

1996 Nationwide X

Natural Gas Industry Methane 

Emission Factor Improvement Study

((URS/UT, 2011)

URS Corporation, 

UT Austin, and U.S. 

Environmental 

Protection Agency

2011 None EF Only

Greenhouse Gas Reporting Program

(U.S. EPA, 2013)

U.S. Environmental 

Protection Agency 2013 Facility Level X

Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2012

(2014 GHG Inventory)

U.S. Environmental 

Protection Agency 2014 Nationwide X

Analysis under subpart OOOO (U.S. 

EPA, 2012a)

U.S. Environmental 

Protection Agency 2012 Nationwide X

Characterizing Pivotal Sources of 

Methane Emissions from Natural Gas 

Production: Summary and Analysis 

of API and ANGA Survey Responses 

(API/ANGA Survey)

American 

Petroleum Institute 

(API)/America’s 

Natural Gas 

Alliance (ANGA)

2012 Regional X

a

Economic Analysis of Methane 

Emission Reduction Opportunities in 

the U.S. Onshore Oil and Natural 

Gas Industries (ICF/EDF Study)

ICF International 

(Prepared for the 

Environmental 

Defense Fund)

2014 Regional X

a. The API/ANGA study provided information on equipment counts that could augment nationwide emissions 

calculations. No source emissions information was included.

The following sections describe emissions data, emission factors, the origin of the 

emission factors, and the methodologies used in the emission estimation process including the 

identification of national populations for several sources of information.

3.1 GRI/EPA Methane Emissions from the Natural Gas Industry, Volume 8: 

Equipment Leaks (GRI/EPA, 1996a)

This report provides an estimate of annual methane emissions from reciprocating and 

centrifugal compressor seals from the natural gas production, processing, transmission and 
9

storage sector using the component method. The component method uses average emission 

factors for reciprocating and centrifugal compressor seals and the average number of 

reciprocating and centrifugal compressors per facility to estimate the average facility emissions. 

The average facility emissions were then extrapolated to a national estimate using the number of 

facilities in each of the sectors.

The emissions data for natural gas production sites were based on screening and bagging 

data collected at 12 oil and gas production sites in the Western U.S. Screening involves using a 

handheld organic vapor analyzer (OVA) or toxic vapor analyzer (TVA) to measure the 

concentration (e.g., parts per million volume, ppmv) of the vented vapors. The method of 

bagging involves enclosing the component to collect venting vapors and measuring the flow rate. 

The measured flow rates from bagged equipment coupled with screening values are used to 

determine the unit-specific mass emission rate. A total of 40 reciprocating compressor seals were 

screened and bagged and an emission factor of 2.37 thousand standard cubic feet per cylinder per 

year (Mscf/cyl-yr) was calculated. No centrifugal compressors were located at any of the 

production sites that were screened.

The reciprocating and centrifugal compressor seal emissions data for the natural gas 

processing, natural gas transmission and natural gas storage sectors were obtained using a GRI 

Hi-FlowTM (trademark of the Gas Research Institute) sampler to quantify emissions and to 

develop emissions factors (GRI/EPA, 1996b). The sampler has a high flow rate and generates a 

flow field around the component that captures the entire leak. As the sample stream passes 

through the instrument, both the flow rate and the total hydrocarbon (THC) concentration are 

measured. The mass emission rate was then determined using these measurements. Different 

emission rates were calculated for the different operating modes of the compressor (GRI/EPA, 

1996b), and were as follows;

 Operating and pressurized;

 Idle and fully pressurized;

 Idle and partially pressurized using a fuel saver system (reciprocating compressors only);

 Idle and depressurized. 
10

The pressurized compressor seal emission rates (operating and idle) were calculated as 

the average of all reciprocating and centrifugal compressor seals combined. The compressor seal 

emission rates were determined to be 599 thousand standard cubic feet per seal per year 

(Mscf/seal-yr) in the operating and pressurized mode, 531 Mscf/seal-yr in the idle and 

pressurized mode, and 116 Mscf/seal-yr in the idle and partially pressurized mode (e.g., fuel 

saver) (GRI/EPA, 1996b). The compressor seal emission rate was assumed to be negligible in the 

idle and depressurized mode. 

Using the percentage of the time pressurized and the compressor seal emission rates for 

the operating modes (e.g., operating and pressurized, idle and pressurized, idle and partially 

pressurized, idle and depressurized), emission factors were calculated for the natural gas 

processing, transmission, and storage segments. A summary of the emissions factors for each of 

these segments and the natural gas production segment are provided in Table 3-2. The number of 

seals was determined by averaging the compressor seal counts from the data in each of the 

segments. The number of centrifugal compressor seals depends on the type of compressor: 

centrifugal compressors with overhung rotors have one seal and beam type compressors have 

two seals. Information from three compressor vendors and one compressor seal vendor showed 

an even split between the two type of centrifugal compressors; therefore, the number of seals per 

centrifugal compressor was averaged to be 1.5.
11

Table 3-2. Summary of Reciprocating and Centrifugal Compressor Seal 

Methane Emission Factors

Type of 

Compressor

Percentage of 

Time the 

Compressor is 

Pressurized (%)

Compressor Seal 

Methane Emission 

Factor 

(Mscf/seal-yr)

Assumed 

Number of Seals 

per Compressor

Average 

Compressor 

Methane Emission 

Factor from Seals

(Mscf/yr)

Natural Gas Production

Reciprocating N/A 2.37 4 9.48

Natural Gas Processing

Reciprocating 89.7 450 2.5 1,125

Centrifugal 43.6 228 1.5 342

Natural Gas Transmission

Reciprocating 79.1 396 3.3 1,307

Centrifugal 24.2 165 1.5 248

Natural Gas Storage

Reciprocating 67.5 300 4.5 1,350

Centrifugal 22.4 126 1.5 189

The GRI/EPA study presented the emissions for reciprocating and centrifugal 

compressors as a sum of the emission components from compressors. These components 

included methane emissions from compressor seals, blowdown open-ended line, pressure relief 

valves, starter open-ended line, and miscellaneous, which includes valves and connectors. For 

the purposes of this paper, only the methane emissions from reciprocating and centrifugal 

compressor seals were calculated using the equipment counts of reciprocating and centrifugal 

compressors and applying the methane emission factor for each of the sectors. A summary of 

these emissions are presented in Table 3-3 for each of the sectors reported in the GRI/EPA study.
12

Table 3-3. Summary of GRI/EPA Methane Emissions from Reciprocating and 

Centrifugal Compressor Seals

Type of 

Compressor

Average Methane 

Emission Factor 

(Mscf/yr)

Activity Factor, 

Compressor 

Count

Annual Methane 

Emissions 

(Mscf/yr)

Average Methane 

Emissions 

(MT/yr)

Natural Gas Production

Reciprocating 9.48 17,152 162,601 3,071

Natural Gas Processing

Reciprocating 1,125 4,092 4,603,500 86,949

Centrifugal 342 726 248,292 4,690

Natural Gas Transmission

Reciprocating 1,307 6,799 8,886,293 167,841

Centrifugal 248 681 168,888 3,190

Natural Gas Storage

Reciprocating 1,350 1,396 1,884,600 35,596

Centrifugal 189 136 25,704 485

Total 15,978,655 301,799

The GRI/EPA study reported methane emissions of 568,670 Mscf/yr (10,741 MT) from 

reciprocating compressors from both Eastern and Western U.S. natural gas production. These 

totals, as stated earlier, include emissions from compressor blowdowns, starter gas, and 

miscellaneous equipment associated with the compressor. Methane emissions from reciprocating 

compressor seals represent approximately 29% of the total emissions from reciprocating 

compressors. Note that the Eastern U.S. natural gas production did not include methane 

emissions from compressor seals in the reciprocating compressor emission factor, only emissions 

from the associated equipment (e.g., valves, connectors, and open-ended lines). Table 3-3 does 
13

include the estimated 129 gathering reciprocating compressors from the Eastern U.S. in the 

activity factor for natural gas production and estimates compressor seal methane emissions using 

the listed reciprocating compressor seal emission factor.

For natural gas processing, the total methane emissions from reciprocating and 

centrifugal compressors and associated equipment and operations were reported as 16,736,280 

Mscf/yr (316,108 MT) and 5,626,500 Mscf/yr (106,271 MT), respectively. The methane 

emissions from reciprocating and centrifugal compressor seals represent 28% and 4.4%,

respectively, of the total methane emissions from reciprocating and centrifugal compressors in 

the natural gas processing sector. In the natural gas transmission sector, the total methane 

emissions from reciprocating and centrifugal compressors were estimated to be 37,734,450 

Mscf/yr (712,714 MT) and 7,559,100 Mscf/yr (142,773 MT), respectively. The methane 

emissions from reciprocating and centrifugal compressor seals represent 24% and 2.2%,

respectively, of the total methane emissions from reciprocating and centrifugal compressors in 

the natural gas processing sector. The total methane emissions from reciprocating and centrifugal 

compressors and their associated equipment were estimated to be 10,763,160 Mscf/yr (203,290 

MT) and 1,517,760 Mscf/yr (28,667 MT), respectively, for the natural gas storage sector. The 

methane emissions from reciprocating and centrifugal compressor seals represents 18% and 

1.7%, respectively, of the total methane emissions from reciprocating and centrifugal 

compressors in the natural gas storage sector.

3.2 Natural Gas Industry Methane Emission Factor Improvement Study, Final Report 

(URS/UT, 2011)

The report describes the effort to update default methane emission factors for selected 

processes and equipment in the natural gas industry. These processes and equipment are believed 

to contribute the greatest uncertainty in the U.S. natural gas industry methane emissions 

inventory and concentrated on high emission rate leaks (fugitive leaks) from transmission,

gathering/boosting, and gas processing reciprocating and centrifugal compressor components,

including emissions from compressor vents (i.e., blowdown lines and compressor seals). 
14

The emissions data were collected at 11 sites in Texas and New Mexico and included 

data from gathering and boosting stations, natural gas processing plants, and transmission 

stations. The sites were all constructed between the 1950s and 2000s. The total number of 

compressors that were measured included 66 reciprocating compressors and 18 centrifugal 

compressors, with 48 of the reciprocating compressors located at transmission compressor 

stations. For compressor seals, the measurements were conducted using the following steps:

 Where the reciprocating compressor rod packing vent lines were piped together (multiple 

cylinders joined into a single vent line for each compressor), the enclosed rotary vane 

anemometer was used to make the measurements at the top of the rod packing vent line;

 Where the reciprocating rod packing vent lines were individually vented to the 

atmosphere, each vent line was measured with a handheld hot wire anemometer; and 

 For centrifugal compressors equipped with wet seals, measurements were made at the 

wet seal degassing fill port to the seal oil pump using plastic bags of known internal 

volume and measuring the required flow to fill the bag.

The study noted several technical issues with measuring emissions from a wet seal 

system including location of the flash emissions and configuration of the seal oil degassing 

system (which may include blowers or a flash drum/pot). The study noted that the wet seal 

measurements from this study should be used as a benchmark and requires further analysis 

before the measurements could be used to develop emission factors.

A summary of the testing results from the study are provided in Table 3-4. The study 

grouped the test results for centrifugal compressors located at natural gas gathering and boosting, 

processing and transmission together. The test data for reciprocating compressors were separated 

into units located at gathering and boosting stations and units located at transmission stations.

The study found that the largest emission sources at a compressor stations are the compressor 

blowdown vent lines and the compressor seal vents (URS/UT, 2011). 
15

Table 3-4. Sampling Results for Reciprocating and Centrifugal Compressor Seals

Compressor Vent Measured Sample Size

Average 

Methane 

Emission 

Factor 

(Mscf/yr)

1996 

GRI/EPA 

Emission 

Factora

(Mscf/yr)

Natural Gas Gathering/Boosting Reciprocating Compressors

Average Rod Packing 15 241 9.48b

Natural Gas Transmission Reciprocating Compressors

Average Rod Packing (Idle + depressurized) 5 12,236

396c

Average Rod Packing 2 29,603

Natural Gas Gathering/Boosting, Processing and Transmission Centrifugal Compressors

Average Wet Seal 9 8,137 396d

a

(GRI/EPA, 1996b)

b Appendix B-4, assumes 4 seals per compressor.

c Table 4-15, adjusted for 79.1% time the compressor is pressurized.

d Table 4-15, adjusted for 24.2% time the compressor is pressurized.

The study authors concluded that the centrifugal compressor wet seal degassing vent 

emissions were much higher in comparison to the GRI/EPA emission factors. The study authors

also determined that the average reciprocating compressor rod packing vent emissions that they 

calculated were significantly higher than the GRI/EPA study (GRI/EPA, 1996b).

3.3 Greenhouse Gas Reporting Program (U.S. EPA, 2013)

In October 2013, the EPA released 2012 greenhouse gas (GHG) data for Petroleum and 

Natural Gas Systems collected under the Greenhouse Gas Reporting Program (GHGRP). The 

GHGRP, which was required by Congress in the FY2008 Consolidated Appropriations Act, 

requires facilities to report data from large emission sources across a range of industry sectors, as 

well as suppliers of certain GHGs and products that would emit GHGs if released or combusted. 
16

When reviewing this data and comparing it to other data sets or published literature, it is 

important to understand the GHGRP reporting requirements and the impacts of these 

requirements on the reported data. The GHGRP covers a subset of national emissions from 

Petroleum and Natural Gas Systems; a facility in the Petroleum and Natural Gas Systems source 

category is required to submit annual reports if total emissions are 25,000 metric tons carbon 

dioxide equivalent (CO2e) or more. Facilities use uniform methods prescribed by the EPA to 

calculate GHG emissions, such as direct measurement, engineering calculations, or emission 

factors derived from direct measurement. In some cases, facilities have a choice of calculation 

methods for an emission source. Because some of the methods required direct measurement of 

emissions or parameters, for an interim period, the EPA made available the optional use of Best 

Available Monitoring Methods (BAMM) for unique or unusual circumstances. Where a facility 

used BAMM, it was required to follow emission calculations specified by the EPA, but was 

allowed to use alternative methods for determining inputs to calculate emissions.

Emissions for both reciprocating and centrifugal compressors are reported under the 

processing, transmission, underground gas storage, and liquid natural gas (LNG) import/export 

and storage segments. The calculation method varied by industry segment. Emissions from 

compressors in onshore production were calculated by using population counts multiplied by an 

emission factor. Emissions from compressors in the other industry segments were calculated by 

the use of direct measurement.

Table 3-4 shows activity data and emissions for reciprocating compressors for the natural 

gas processing, natural gas transmission, and underground natural gas storage industry segments. 

The EPA received data for 4,466 reciprocating compressors, including 2,149 reciprocating 

compressors in natural gas processing, 2,008 reciprocating compressors in natural gas 

transmission, and 309 reciprocating compressors in underground natural gas storage. Of the 

reciprocating compressors, BAMM was used to calculate emissions for 1,847 compressors, 

including 993 in natural gas processing, 790 in natural gas transmission, and 64 in underground 

natural gas storage.
17

Table 3-5. 2012 Direct Measurement Reported Process Emissions from Reciprocating 

Compressors from Natural Gas Processing, Natural Gas Transmission 

and Underground Natural Gas Storage

Industry Segment

Total 

Number of

Reciprocating

Compressors

Number of

Reciprocating

Compressors 

that used BAMM

Reported

CH4

Emissions

(MT CO2e)

Reported

CH4

Emissionsa

(MT)

Natural Gas Processing 2,149 993 1,009,045 48,050

Natural Gas Transmission 2,008 790 1,591,990 75,809

Underground Natural Gas 

Storage 309 64 160,809 7,658

Total 4,466 1,847 2,761,844 131,516

a. Conversion factors MT CO2e to tons: 21 MT CH4/MT CO2e

Table 3-6 shows activity data and emissions for centrifugal compressors for the natural 

gas processing, natural gas transmission, and underground natural gas storage industry segments. 

For centrifugal compressors the number of compressors with wet seals is also shown. Overall 

emissions from centrifugal compressors were lower than those for reciprocating compressors, but 

the total number of reported compressors was lower as well. The EPA received data for 1,191

centrifugal compressors, including 428 centrifugal compressors in natural gas processing, 724 

centrifugal compressors in natural gas transmission, and 39 centrifugal compressors in 

underground natural gas storage. Of these centrifugal compressors, BAMM was used to calculate 

emissions for 538 compressors, including 234 in natural gas processing, 292 in natural gas 

transmission, and 12 in underground natural gas storage.
18

Table 3-6. 2012 Direct Measurement Reported Process Emissions from Centrifugal 

Compressors from Natural Gas Processing, Natural Gas Transmission 

and Underground Natural Gas Storage

Industry Segment

Total Number 

of Centrifugal

Compressors

Number of

Centrifugal

Compressors 

that used 

BAMM

Number of

Centrifugal

Compressors 

with Wet 

Seals

Reported

CH4

Emissions

(MT CO2e)

Reported

CH4

Emissionsa

(MT)

Natural Gas 

Processing 428 234 274 752,054 35,812

Natural Gas 

Transmission 724 292 291 439,714 20,939

Underground

Natural Gas

Storage

39 12 23 118,500 5,643

Total 1,191 538 588 1,310,268 62,394

a. Conversion factors: 21 MT CH4/MT CO2e

3.4 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012 (U.S. EPA, 2014)

The EPA leads the development of the annual Inventory of U.S. Greenhouse Gas 

Emissions and Sinks (GHG Inventory). This report tracks total U.S. GHG emissions and 

removals by source and by economic sector over a time series, beginning with 1990. The U.S. 

submits the GHG Inventory to the United Nations Framework Convention on Climate Change 

(UNFCCC) as an annual reporting requirement. The GHG Inventory includes estimates of 

methane and carbon dioxide for natural gas systems (production through distribution) and 

petroleum systems (production through refining).

The 2014 GHG Inventory (published in 2014; containing emissions data for 1990-2012) 

calculates net methane emissions for reciprocating compressors using emission factors based on 

the GRI/EPA study (GRI/U.S. EPA, 1996a). The factors are used to develop potential emissions. 

The total potential emissions are reduced by known controls or practices that reduce emissions to 

calculate net emissions. For centrifugal compressors, the EPA has developed emission factors for 

both wet seal and dry seal compressors that are used to directly calculate net emissions (i.e., after 

control). 
19

For the natural gas production stage, emission factors for gathering compressors are 

regional and cover small and large reciprocating compressors (no centrifugal compressors). 

For natural gas processing, and transmission and storage, the emission factors are for 

reciprocating compressors and the two types of centrifugal compressors (wet and dry seal). For 

LNG storage and import/export, there are factors for reciprocating and centrifugal compressors. 

The emission factors used to calculate methane emission for compressors for the 2014 GHG 

Inventory are summarized in Table 3-8.

Table 3-9 summarizes the activity data and 2012 calculated potential methane emissions 

for compressors by industry segment and compressor type.

Table 3-8. Natural Gas Sector Methane Emission Factors for Compressors

Emission Factor (scf/day/compressor)

Industry Activity

Reciprocating Centrifugal

Small

1 Large Wet Seal Dry Seal

Production 263-312 14,947-17,728 -

Processing 11,196 51,370 25,189

Transmission 15,205 50,222 32,208

Storage 21,116 45,441 31,989

LNG Storage/Import 21,116 30,573

 

1 The GRI/EPA study defines small gathering compressors as compressors on the overhead lines from gas well 

separators and associated gas well separators. Large gathering compressors are compressors at large gathering 

compressor stations (stations with 8 compressors or more).
20

Table 3-9. Summary of Natural Gas Sector Compressor Activity and 

Calculated Potential Methane Emissions

Industry Segment

Activity

(Compressor 

Units)

Calculated 

Potential Methane 

Emissions (MT)

Production

Reciprocating (small) 35,930 70,859

Reciprocating (large) 136 15,400

Processing

Reciprocating 5,624 442,634

Centrifugal (wet seal) 658 237,724

Centrifugal (dry seal) 248 43,937

Transmission

Reciprocating 7,235 773,294

Centrifugal (wet seal) 659 232,826

Centrifugal (dry seal) 66 14,972

Storage

Reciprocating 1,012 150,225

Centrifugal (wet seal) 70 22,347

Centrifugal (dry seal) 29 6,532

LNG Storage

Reciprocating 270 40,147

Centrifugal 64 13,766

LNG Import Terminal

Reciprocating 37 5,552

Centrifugal 7 1,419

The GHG Inventory emissions calculations used regional values by industry segment for 

the methane content in natural gas. The average national value for general sources was 83.3%

methane for 2012. 

The net 2012 methane emissions reported for compressors for the 2014 GHG Inventory 

were 86,259 MT for the natural gas production segment, 724,295 MT for the natural gas

processing segment, and 1,261,080 MT for the natural gas transmission and storage segment, for 

a total of 2,071,633 MT of methane. 
21

3.5 Development of the New Source Performance Standard (NSPS) For Oil and Natural 

Gas Production (U.S. EPA, 2011b and U.S. EPA, 2012a)

2

VOC emission factors were developed for reciprocating and centrifugal compressors in 

order to support the development of subpart OOOO. In order to develop these factors the EPA 

used information from the GHGRP3, the GHG Inventory, the EPA’s Natural Gas STAR 

Program, and a study by the GRI/EPA study. Updates to the GHGRP and the GHG Inventory 

have occurred since this analysis, however, it is presented here for completeness.

The methodology for estimating emissions from reciprocating compressor rod packing 

was to use the methane emission factors referenced in the EPA/GRI study (GRI/EPA, 1996a)

and use the methane-to-pollutant ratios developed in the gas composition memorandum

developed for subpart OOOO. (EC/R, 2011) The emission factors in the EPA/GRI study were 

expressed in thousand standard cubic feet per cylinder (Mscf/cyl), and were multiplied by the 

average number of cylinders per reciprocating compressor at each oil and gas industry segment. 

The volumetric methane emission rate was converted to a mass emission rate using a density of 

41.63 pounds of methane per thousand cubic feet. This conversion factor was developed 

assuming that methane is an ideal gas and using the ideal gas law to calculate the density. 

The centrifugal compressor emission factors for wet seals and dry seals were based on 

emission factors from the 2012 GHG Inventory (published in 2012; containing emissions data 

for 1990-2010). The wet seal methane emission factor was calculated based on a sampling of 48 

wet seal centrifugal compressors. The dry seal methane emission factor was based on data 

collected by the Natural Gas STAR Program. The methane emissions were converted to VOC 

emissions using the same gas composition ratios that were used for reciprocating engines. (EC/R, 

2011) A summary of the methane emission factors is presented in Table 3-10.

 

2 Unless otherwise indicated, the following sections are excerpts from either Section 6 of the technical support 

document for the proposed subpart OOOO (U.S. EPA, 2011b) or Section 6.0 of the technical support document for 

the final subpart OOOO rule (U.S. EPA, 2012a).

3

http://www.epa.gov/ghgreporting/
22

Table 3-10. Methane Emission Factors for Reciprocating and Centrifugal Compressors

Oil and Gas 

Industry 

Segment

Reciprocating Compressors Centrifugal Compressors

Methane 

Emission Factor 

(scf/hr-cylinder)

Average 

Number of 

Cylinders

per 

Compressor

Pressurized 

Factor (% of 

hour/year 

Compressor 

Pressurized)

Wet Seal 

Methane 

Emission 

Factor 

(scf/minute)

Dry Seals 

Methane 

Emission 

Factor 

(scf/minute)

Production 

(Well Pads) 0.271a

4 100% N/Af N/Af

Gathering & 

Boosting 25.9b

3.3 79.1% N/Af N/Af

Processing 57c2.5 89.7% 47.7g6

g

Transmission 57d3.3 79.1% 47.7g6

g

Storage 51e4.5 67.5% 47.7g6

g

a

(GRI/EPA, 1996a), Table 4-8. 

b Clearstone Engineering Ltd. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five 

Gas Processing Plants and Upstream Gathering Compressor Stations and Well Sites.: 2006.

c

(GRI/EPA, 1996a), Table 4-14. 

d

(GRI/EPA, 1996a) Table 4-17. 

e

(GRI/EPA, 1996a) Table 4-24. 

f The 1996 EPA/GRI Study Volume 114

, does not report any centrifugal compressors in the production or 

gathering/boosting sectors; therefore, no emission factor data were published for those two sectors. 

g

(U.S. EPA, 2011a), Annex 3. Page A-153. 

Source: Derived from (U.S. EPA, 2011b), Table 6-2 and (U.S. EPA, 2012a), Table 6-1

Once the methane emission rates for compressors were calculated using the emission 

factors, ratios were applied to the methane emissions to estimate VOC emissions. The specific 

ratios that were used for this analysis were 0.278 pounds VOC per pound of methane for the 

production and processing segments, and 0.0277 pounds VOC per pound of methane for the 

transmission and storage segments. A summary of the baseline individual compressor emission

rates are shown in Table 3-11 for each of the oil and gas industry segments.

 

4 EPA/GRI (1996) Methane Emission from the Natural Gas Industry, Vol. 11, .Pages 11 – 15. Available at: 

http://epa.gov/gasstar/documents/emissions_report/11_compressor.pdf
23

Table 3-11. Baseline Emission Rates for Reciprocating and 

Centrifugal Compressors

Industry Segment/

Compressor Type

Baseline Emission Estimates

(tons/compressor/year)

Methane VOC 

Reciprocating Compressors

Production (Well Pads) 0.198 0.0549

Gathering & Boosting 12.3 3.42

Processing 23.3 6.48

Transmission 27.1 0.751

Storage 28.2 0.782

Centrifugal Compressors (Wet seals)

Processing 228 20.5

Transmission 126 3.50

Storage 126 3.50

Centrifugal Compressors (Dry seals)

Processing 28.6 2.58

Transmission 15.9 0.440

Storage 15.9 0.440

Source: Derived from (U.S. EPA, 2011b), Table 6-2 and (U.S. EPA, 2012a), Table 6-1

The analysis performed in the technical support document (TSD) to proposed subpart 

OOOO (U.S. EPA, 2011b) was designed to provide information about new compressors for the 

purposes of establishing new source performance standards; accordingly, the analysis did not 

estimate nationwide emissions for all compressors.
24

3.6 Characterizing Pivotal Methane Emissions from the Oil and Natural Gas Sector, 

(API /ANGA, 2012)

The API/ANGA study (API/ANGA, 2012) is an analysis of industry survey data that 

includes data from over 20 companies covering over 90,000 gas wells. This study sample 

population includes representation from most of the geographic regions of the country as well as 

most of the geologic formations currently developed by the industry. 

With respect to compressors, the API/ANGA study collected information related to the 

activity count for centrifugal compressors, specifically to supplement the EPA’s data on the 

prevalence of wet seal and dry seal compressors in the industry. According to the survey results, 

the data collected represented approximately 5% of the national centrifugal compressor count for 

gas processing operations (38 centrifugal compressors from the survey, compared to 811 from 

2012 GHG Inventory). Of the gas processing centrifugal compressors reported through the 

survey, 79% were dry seal compressors and 21% were wet seal units. If the results of the survey 

were considered to be representative, the authors assert that the EPA’s current ratio of 80% wet 

seal and 20% dry seals severely overestimates the emissions from the wet seal compressors. 

Based on the emission factors from Table A-123 of Annex 3 of the 2012 GHG Inventory, the

methane emissions from centrifugal compressors would be 190,573 tons (172,887 MT)

compared to 288,068 tons (261,334 MT) from the 2012 GHG Inventory. This would equate to an 

approximate 34% reduction in the emissions from this source. The authors recommended using 

the GHGRP data to further refine these activity numbers. 

With respect to production and gathering facilities that use centrifugal compressors, the 

API/ANGA survey responses reported only 550 centrifugal compressors associated with 

production and gathering at 21 participating companies. The authors noted that the 2012 GHG 

Inventory did not include centrifugal compressors in production/gathering operations. The study 

reported that, on a well basis, the survey response equates to 0.07 centrifugal compressor per gas 

well with 81% of those being dry seal and the remaining being wet seal. The authors 

recommended that the EPA continue to refine these numbers using data from the GHGRP. 
25

3.7 Economic Analysis of Methane Emission Reduction Opportunities in the U.S. 

Onshore Oil and Natural Gas Industries (ICF International, 2014)

The Environmental Defense Fund (EDF) commissioned ICF International (ICF) to 

conduct an economic analysis of methane emission reduction opportunities from the oil and 

natural gas industry to identify the most cost-effective approach to reduce methane emissions 

from the industry. The study projects the estimated growth of methane emissions through 2018 

and focuses its economic analysis on 22 methane emission sources in the oil and natural gas 

industry (referred to as the targeted emission sources). These targeted emission sources represent 

80% of the study’s projected 2018 methane emissions from onshore oil and gas industry sources. 

Centrifugal compressor and reciprocating compressor emission sources were included in their 

list of targeted emission sources. 

The study relied on the 2013 GHG Inventory for methane emissions data for the oil and 

natural gas sector. These emissions data for compressors were revised to include updated 

information from the GHGRP, data from the 1996 GRI/EPA study of methane emissions, 

information on the Federal Energy Regulatory Commission (FERC) website, data obtained from 

the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration 

and information from various state energy and environmental departments. The revised ICF 2011 

baseline methane emissions estimates were then used as the basis for projecting onshore methane 

emissions to 2018. A summary of the most significant revisions made to the 2013 GHG 

Inventory activity and emission factors to develop the revised ICF 2011 baseline by industry 

segment are presented in Section 3.8.1. The methodology used to project onshore methane 

emissions from the revised 2013 GHG Inventory (referred to as the ICF 2011 baseline) to 2018 

for compressors is presented in Section 3.8.2.

3.7.1 ICF 2011 Baseline 

The ICF study breaks out emissions by natural gas segment (gas production, gathering 

and boosting, gas processing, gas transmission, gas storage, LNG and gas distribution) and 

petroleum segment (oil production, oil transportation and oil refining). The most significant 

revisions made to the 2013 GHG Inventory to develop the ICF 2011 baseline for compressors are 
26

summarized by industry segment in the following paragraphs. Note that no emission factor or 

activity changes related to compressors were made for the gas production, oil production, oil 

transportation, and oil refining segments.

3.7.1.1 Gathering and Boosting Segment

Reciprocating Compressors

 Updated the 1996 EPA/GRI study emissions factors used in the 2013 GHG Inventory 

using information obtained from five state energy agencies (Texas, Colorado, Wyoming, 

Oklahoma and Pennsylvania) on permitted engines for production and gathering 

compressors in the petroleum and natural gas industry. These data were split into large 

and small compressors using the 1,600 horsepower (hp) threshold from the 1996 

EPA/GRI study. The state data showed a larger percentage of large compressors than 

assumed in the 2013 GHG Inventory. A new weighted average factor was calculated 

using the 1996 EPA/GRI study emission factors. The new methane emission factor for all 

gathering compressors was calculated at 1,980 scf/day/compressor. 

 The reciprocating compressor emission factor used in the 2013 GHG Inventory was 

updated to distinguish compressor seal emissions versus compressor fugitives (which are 

combined in the GHG Inventory) using the 1996 EPA/GRI study emission factors, 

whereby compressors seals were then separated into two categories: reciprocating 

compressors – non-seals (75%) and reciprocating compressors – seals (25%).

 Developed new activity factors for reciprocating compressors using information obtained 

from the five state energy agencies (discussed above) by using the 2013 GHG Inventory 

ratio of compressors in these five states to the national count of compressors to obtain a 

new national reciprocating compressor count of 15,687. 

Based on these revisions, ICF estimated the net change in methane emissions from 

reciprocating compressors (as compared with the 2013 GHG Inventory) to be 166% or an 

increase to 11 Bcf (228,965 tons).
27

Centrifugal Compressors

 Created a new emission category for wet seal centrifugal compressors based on 

information obtained from the GHGRP that included 162 wet seal centrifugal 

compressors used in the upstream sector. ICF assumed that the respondents under the 

GHGRP represented 85% of the industry. Therefore, ICF adjusted the number of wet seal 

centrifugal compressors to be 191. ICF used an emission factor of 12,000,000 

scf/year/compressor (from subpart W) and their estimated number of wet seal centrifugal 

compressors to estimate methane emissions for the 2011 baseline (over 2 Bcf [41,630 

tons] methane).

3.7.1.2 Gas Processing

 Reciprocating compressors emission factor updated to breakout emissions from 

compressor seals versus “other” compressor fugitives as discussed in Section 3.8.1.1.

3.7.1.3 Gas Transmission

 Number of compressor stations revised from 1,808 to 1,768 (based on a change in 

pipeline miles included in the 2013 GHG Inventory using data obtained from the U.S. 

Department of Transportation Pipeline and Hazardous Materials Safety Administration 

indicating a lower value for transmission pipeline miles), resulting in an emissions 

decrease of just over 2%. 

 Number of reciprocating compressors changed from 7,270 to 7,111 (based on changes to 

the pipeline miles included in the 2013 GHG Inventory – see above), resulting in an 

emissions decrease of over 2%.

 Number of centrifugal compressors revised from 654 to 648 (based on changes to the

pipeline miles included in the 2013 GHG Inventory – see above), resulting in an 

emissions decrease of over 2%.
28

3.7.1.4 Gas Storage

 Reciprocating compressors emission factor updated to breakout emissions from 

compressor seals versus “other” compressor fugitives as discussed in Section 3.8.1.1.

3.7.2 ICF Projections to 2018

Emissions projections are not the subject of this paper; therefore, the estimates of 2018 

emissions produced in the ICF study are not presented here. However, the ICF study uses the 

projections to evaluate emissions mitigation techniques for compressors, which are addressed in 

this paper. Those mitigation techniques are discussed in detail in Section 4 of this paper. The 

methodology the ICF study used to project emissions to 2018 is described here in order to 

provide context for the later discussion of mitigation techniques.

The primary sources used for projecting onshore methane emissions for centrifugal and 

reciprocating compressors for 2018 included the INGAA Foundation North American Midstream 

Infrastructure Through 2035-A Secure Energy Future report (ICF, 2011), an analysis of past 

projected infrastructure change, FERC and ICF information on emission reductions anticipated 

as a result of regulation (40 CFR Part 60, subpart OOOO). 

The INGAA report provided yearly forecast information of incremental gathering 

pipeline miles, gas processing plants and processing compressor counts that were used with 

existing activity data from the 2013 GHG Inventory to estimate a regional activity factor for use 

to make projections out to 2018. For the gathering and boosting segment, the activity factors 

were estimated based on a ratio of pipeline miles in 2018 to pipeline miles in the ICF 2011 

baseline to obtain 2018 activity levels. For the gas processing segment, the activity factors were 

estimated based on a ratio between the compressor count in 2018 and the compressor count in 

the ICF 2011 baseline. For the gas transmission segment, projections out to 2018 were based on 

an analysis of past pipeline infrastructure changes, where the change in the length of 

transmission pipeline from 1990 to 2011 was used to establish an incremental value based on 

trends that were then used to project the pipeline miles for 2018. 
29

The new 2018 forecast of emissions for centrifugal and reciprocating compressors (for all 

but production and transmission segments) were adjusted to account for emission reductions that 

are expected as a result of the EPA’s NSPS, subpart OOOO. 

Further information included in this study on mitigation or emission reduction options, 

methane control costs, and their estimates for the potential for VOC emissions co-control

benefits from their use is presented in Section 4 of this document. 

4.0 AVAILABLE COMPRESSOR EMISSIONS MITIGATION 

TECHNIQUES

Emissions mitigation options for reciprocating compressors involve techniques that limit 

the leaking of natural gas past the piston rod packing, including replacement of the compressor 

rod packing, replacement of the piston rod, and the refitting or realignment of the piston rod. The 

EPA is also aware of new technologies that enable the emissions to be captured and either routed 

to a combustion device or a useful process. Emission mitigation options for centrifugal 

compressors limit the leaking of natural gas across the rotating shaft using a mechanical dry seal, 

or capture the gas and route it to a useful process or to a combustion device. A discussion of 

these techniques and their costs is presented in the following sections.

4.1 Reciprocating Compressor - Rod Packing Replacement

4.1.1 Description

The potential emission reduction options for reciprocating compressors include control 

techniques that limit the leaking of natural gas past the piston rod packing. Reciprocating 

compressor rod packing consists of a series of flexible rings that fit around a shaft to create a seal 

against leakage. Rod packing emissions typically occur around the rings from slight movement 

of the rings in the cups as the rod moves, but can also occur through the “nose gasket” around the 

packing case, between the packing cups, and between the rings and shaft (see Figure 2-1). 

Mitigation options for these emissions include replacement of the compressor rod packing, 
30

replacement of the piston rod, and the refitting or realignment of the piston rod (U.S. EPA, 

2006a).

The replacement of the rod packing is a maintenance task performed on reciprocating 

compressors to reduce the leakage of natural gas past the piston rod. Over time, the packing rings 

wear and allow more natural gas to escape around the piston rod. Regular replacement of these 

rings reduces VOC and methane emissions. 

Like the packing rings, piston rods on reciprocating compressors also deteriorate. Rods 

can wear “out-of-round” or taper when poorly aligned, which affects the fit of packing rings 

against the shaft (and therefore the tightness of the seal) and the rate of ring wear. Replacing or 

upgrading the rod can reduce reciprocating compressor rod packing emissions. Also, upgrading 

piston rods by coating them with tungsten carbide or chrome reduces wear over the life of the 

rod (U.S. EPA, 2006a).

4.1.2 Effectiveness

As discussed above, regular replacement of the reciprocating compressor rod packing can 

reduce the leaking of natural gas across the piston rod. The emission reductions are related to the 

rate of deterioration and the frequency of replacement.

Subpart OOOO Technical Support Document (U.S. EPA, 2011b)

In the TSD for the subpart OOOO rulemaking, the expected emission reductions from a 

rod packing replacement were calculated by comparing the average rod packing emissions with 

the average emissions from newly installed and worn-in rod packing (U.S. EPA, 2011b). For

gathering and boosting compressors, the analysis calculated the potential methane emission 

reductions by multiplying the number of new reciprocating compressors by the difference 

between the average rod packing emission factor in Table 3-10 by the average emission factor 

from a newly installed rod packing. The average rod packing emission factor used for gathering 

and boosting compressors was developed from the Clearstone II study (Clearstone, 2006) using 

rod packing measurement data (which was adjusted for the percent of time transmission 
31

compressors are operating) (GRI/U.S. EPA, 1996). For wellhead reciprocating compressors, the

analysis calculated a percentage reduction using the transmission emission factor from the 1996 

EPA/GRI report and the minimum emissions rate from a newly installed rod packing to 

determine methane emission reductions. The emission reductions for the processing, 

transmission, and storage segments were calculated by multiplying the number of new 

reciprocating compressors in each segment and the difference between the average rod packing 

emission factors in Table 3-10 (GRI/U.S. EPA, 1996) and the average emission factor from 

newly installed rod packing. Newly installed packing average methane emissions were assumed 

to be 11.5 cubic feet per hour per cylinder (U.S. EPA, 2006a).

A summary of the estimated emission reductions for reciprocating rod packing 

replacement for each of the oil and gas segments from the subpart OOOO TSD is shown in Table 

4-1. The emissions of VOC were calculated using the methane emission reductions calculated 

above and the gas composition (EC/R, 2011) for each of the segments. 

Table 4-1. Estimated Annual Individual and Nationwide Emission Reductions from 

Replacing Rod Packing in Reciprocating Compressors

Oil & Gas Segment

Individual Compressor 

Emission Reductions 

(tons/compressor-year)

Methane VOC

Production (Well Pads) 0.158 0.0439

Gathering & Boosting 6.84 1.90

Processing 18.6 5.18

Transmission 21.7 0.600

Storage 21.8 0.604
32

Economic Rod Packing Replacement

The Natural Gas STAR Lessons Learned document titled “Reducing Methane Emissions 

from Compressor Rod Packing Systems” (U.S. EPA, 2006a) states that a new, properly installed 

rod packing system should leak approximately 11 to 12 standard cubic feet per hour (scfh) of 

gas. The effectiveness of the system on minimizing leaks is reliant on the fit of, and wear to the 

rod packing components (such as the rod packing material, the cups that hold it, and the piston 

rod). As the rod packing system ages, the leak rates will increase. Eventually, the leak rate will 

reach a point where the amount of gas saved by replacing the rod packing will justify the cost of 

performing the replacement. In some cases, the economic threshold for replacement can be as 

low as 30 scfh of gas leakage. However, if the rod packing systems are not well maintained, the 

leakage rates can far exceed that value. In one instance, a Natural Gas STAR partner reported 

emissions from an aging rod packing system to be as high as 900 scfh.

Updated rod packing components made from newer materials can also help improve the 

life and performance of the rod packing system. Another potential option is replacing the bronze 

metallic rod packing rings with longer lasting carbon-impregnated Teflon rings. Compressor rods 

can also be coated with chrome or tungsten carbide to reduce wear and extend the life of the 

piston rod (U.S. EPA, 2006a).

4.1.3 Cost of Controls

The Natural Gas STAR Lessons Learned document estimates the cost to replace the 

packing rings on reciprocating compressors to be $1,620 per cylinder. The replacement of rod 

packing for reciprocating compressors occurs on average every four years based on industry 

information from the Natural Gas STAR Program. (U.S. EPA, 2006a)

The TSD for the subpart OOOO rulemaking used the above costs from the Natural Gas 

STAR Lessons Learned document and operating factors from the GRI/EPA study to determine 

the costs and gas savings from rod packing replacement (U.S. EPA, 2011b). The weighted hours, 

on average, per year the reciprocating compressor is pressurized was calculated to be 98.9%
33

using the operating factors presented in Table 3-2 of this paper (GRI/EPA, 1996a). The 

calculated years were assumed to be the equipment life of the compressor rod packing. Table 3-2

was used to estimate the average number of cylinders per compressor for each industry segment. 

Information reviewed did not identify any annual or periodic maintenance costs for the rod 

packing systems. Because replacement of rod packing systems reduces gas emissions, a 

monetary savings can be realized that is associated with the amount of gas saved with 

reciprocating compressor rod packing replacement. The savings were estimated using a natural 

gas price of $4.00 per Mcf (U.S. EIA, 2010). This gas price was used to calculate the annual 

savings using the methane emission reductions in Table 4-1. The savings over the useful 

equipment life of the rod packing system was then calculated based on equipment life discussed 

above. A summary of the estimated capital costs and estimated gas savings for each of the oil 

and gas segments is shown in Table 4-2.

Table 4-2. Capital Cost and Gas Savings for Reciprocating Compressor 

Rod Packing Replacement

Oil and Gas Segment

Capital Cost per 

compressor

($2008)

Gas Savings for 

Equipment Life 

per Compressor 

Production $6,480 $2,493

Gathering & Boosting $5,346 $1,669

Processing $4,050 $1,413

Transmission $5,346 $1,669

Storage $7,290 $2,276

The ICF International study (ICF, 2014) evaluated the effectiveness of replacing rod 

packing systems in reciprocating compressors for existing sources to reduce methane emissions 

assuming 98% control with timely replacement to minimize emissions. Their analysis assumed 

capital costs of $2,000 every 3 years for replacement of the packing system, and revenue benefits 

from reduction of methane emission losses of $3,500 (at $4.00/Mcf gas). The estimated payback 
34

period for this control option was estimated to be seven months. National emission reductions 

were estimated to be 3.6 Bcf (74,934 tons) methane/yr. ICF estimated national annualized costs 

of replacing rod packing systems to be $22.3 million/yr and total initial capital costs to be an 

estimated $182.3 million. ICF also estimated that VOC emissions would be reduced by 8 

kilotons (or approximately 8,816 tons) at a cost of $2,784/ton of VOC reduced. ICF concluded 

that replacing rod packing systems in reciprocating compressors can significantly reduce 

methane emissions and increase savings.

4.2 Reciprocating Compressor – Gas Recovery

4.2.1 Description

The potential emission reduction options for reciprocating compressors include control 

techniques that recover natural gas leaking past the piston rod packing. The EPA is aware of one 

company, REM Technology, Inc., that has developed a system that captures the gas that would 

otherwise be vented and routes it back to the compressor engine to be used as fuel (REM, 2012). 

The vent gases are passed through a valve train that includes a demister and then are injected into 

the engine intake air after the air filter. The EPA is aware that this technology has been deployed 

commercially, but does not have any information on the extent it is used in the field.

Another method for capturing emissions from reciprocating compressor rod packing 

vents is to manifold the vent line to a vapor recovery unit (VRU) system. A VRU is a simple 

system designed to capture vented gas streams, usually from tanks, that would otherwise go to 

the atmosphere. The main components of the system include a compressor and scrubber. If a 

VRU system is already in place at a facility with reciprocating compressors, it is often possible 

to route the vent streams to tanks, allowing the vented rod packing gas to be picked up by the 

VRU. The recovered gas can then be sold or routed for fuel or other meaningful use onsite. If the 

gas cannot be used productively, it can also be sent to a flare system. While flaring may have a 

higher cost than venting to the atmosphere, this practice can reduce methane and VOC

emissions.
35

4.2.2 Effectiveness

REM Technology estimates that the gas recovery system can result in the elimination of 

over 99% of VOC and methane emissions that would otherwise occur from the venting of the

emissions from the compressor rod packing (REM, 2013). The emissions that would have been 

vented are combusted in the compressor engine to generate power. This technique is discussed 

further in the Natural Gas STAR PRO Fact Sheet titled “Install Automated Air/Fuel Ratio 

Controls” (U.S. EPA, 2011c). This document reported an average fuel gas savings of 78 

thousand cubic feet per day (Mcfd) per engine with the gas recovery system installed.

If the facility is able to route rod packing vents to a VRU system, it is possible to recover 

approximately 95-100% of emissions. If the gas is routed the gas to a flare, approximately 95% 

of the methane and VOCs are reduced.

4.2.3 Cost of Controls

The EPA has not been able to obtain cost data on the REM technology. Some costs 

would be mitigated by fuel gas savings, as using the captured gas to displace some of the 

purchased fuel would require less fuel to be purchased in order to run the compressor engine.

For a VRU, assuming the proper equipment is already available at the facility, capturing 

the rod packing gas would require minimal costs. The investment would only need to include the 

cost of piping and installation. While the EPA has not obtained a cost estimate specifically for 

routing rod packing vents to a VRU, this process has been studied for dehydrators and would be 

similar for rod packing systems. According to the Natural Gas STAR PRO Fact Sheet titled 

“Pipe Glycol Dehydrator to Vapor Recovery Unit” (U.S. EPA, 2011d), the cost for planning and 

installing additional piping is approximately $2,000. Routing to a VRU also provides additional 

incentive as there is a value associated with recovered gas. However, the installation of a VRU to 

only capture rod packing emissions may not be economically viable if an additional compressor 

system is required. If the VRU is already present at the facility, the incremental cost to capture 

the rod packing vent gas can be recovered from the value of the additional captured gas.
36

4.3 Centrifugal Compressor - Dry Seals

4.3.1 Description

Centrifugal compressor dry seals operate mechanically under the opposing force created 

by hydrodynamic grooves and springs. The hydrodynamic grooves are etched into the surface of 

the rotating ring affixed to the compressor shaft. When the compressor is not rotating, the 

stationary ring in the seal housing is pressed against the rotating ring by springs. When the 

compressor shaft rotates at high speed, compressed gas has only one pathway to leak down the 

shaft, and that is between the rotating and stationary rings. This gas is pumped between the rings 

by grooves in the rotating ring. The opposing force of high-pressure gas pumped between the 

rings and springs trying to push the rings together creates a very thin gap between the rings 

through which little gas can leak (see Figure 2-3). While the compressor is operating, the rings 

are not in contact with each other; therefore, they do not wear or need lubrication. O-rings seal 

the stationary rings in the seal case. 

Dry seals reduce emissions and, at the same time, they reduce operating costs and 

enhance compressor efficiency. Economic and environmental benefits of dry seals include:

 Gas Leak Rates. Wet seals generate vented emissions during degassing of the circulating 

oil. Gas separated from the seal oil before the oil is recirculated is usually vented to the 

atmosphere, bringing the total leakage rate for tandem wet seals to 47.7 scfm natural gas

per compressor (U.S. EPA/ICR, 2009) (U.S. EPA, 2011a, Annex 3, page A-153).

 Mechanically Simpler. Dry seal systems do not require additional oil circulation 

components and treatment facilities. 

 Reduced Power Consumption. Because dry seals have no accessory oil circulation pumps 

and systems, they avoid “parasitic” equipment power losses. Wet seal systems require 50 

to 100 kW per hour, while dry seal systems need about 5 kW of power per hour.

 Improved Reliability. The highest percentage of downtime for a compressor using wet 

seals is due to seal system problems. Dry seals have fewer ancillary components, which 

translates into higher overall reliability and less compressor downtime.
37

 Lower Maintenance. Dry seal systems have lower maintenance costs than wet seals 

because they do not have moving parts associated with oil circulation (e.g., pumps, 

control valves, relief valves, and the seal oil cost itself).

 Elimination of Oil Leakage from Wet Seals. Substituting dry seals for wet seals 

eliminates seal oil leakage into the pipeline, thus avoiding contamination of the gas and 

degradation of the pipeline.

4.3.2 Effectiveness

The emissions reduction effectiveness of the dry seals was calculated in the TSD for the 

proposed subpart OOOO (U.S. EPA, 2011b) by subtracting the dry seal emissions from a 

centrifugal compressor equipped with wet seals. The centrifugal compressor emission factors in 

Table 3-2 were used in combination with an operating factor of 43.6% for processing centrifugal 

compressors and 24.2% for transmission centrifugal compressors. The operating factors are used 

to account for the percent of time in a year that a compressor is in the operating mode. The 

operating factors for the processing and transmission sectors are based on data in the EPA/GRI 

study (GRI/EPA, 1996a). The wet seals emission factor is an average of 48 different wet seal 

centrifugal compressors. The dry seal emission factor is based on information from the Natural 

Gas STAR Program (U.S. EPA, 2006b). A summary of the emission reduction from the 

replacement of wet seals with dry seals is shown in Table 4-3.

Table 4-3. Estimated Annual Centrifugal Compressor Emission Reductions from 

Replacing Wet Seals with Dry Seals

Oil & Gas Segment

Individual Compressor Emission Reductions

(ton/compressor-year)

Methane VOC

Processing 199 18.0

Transmission/Storage 110 3.06
38

4.3.3 Cost of Controls

The price difference between a brand new dry seal and brand new wet seal centrifugal 

compressor is small relative to the cost for the entire compressor. The analysis in the TSD for 

proposed subpart OOOO assumed the additional capital cost for a dry seal compressor to be

$75,000, with an equipment life of 10 years (U.S. EPA, 2011b). 

The Natural Gas STAR Program estimated that the operation and maintenance savings 

from the installation of dry seals is $88,300 annually in comparison to wet seals (U.S. EPA,

2006b). Monetary savings associated with the amount of gas saved with the replacement of wet 

seals with dry seals for centrifugal compressors was estimated using a natural gas price of $4.00 

per Mcf (U.S. EIA, 2010). This cost was used to calculate the annual gas savings using the 

methane emission reductions in Table 4-2. There is no gas savings cost benefits for transmission 

and storage facilities, because it is assumed the owners of the compressor station do not own the 

natural gas that is compressed at the station. A summary of the capital cost, annual operation and 

maintenance cost and the natural gas savings for replacing wet seals with dry seals is presented 

in Table 4-4. As shown in the table, there is a net savings after one year of operation without 

considering any potential natural gas savings.

Table 4-4. Costs for Replacing Centrifugal Compressor Wet Seals with Dry Seals

Oil and Gas Segment

Capital Cost

per compressor 

($2008)

Annual Operation and 

Maintenance Savings

($/compressor)

Annual Natural Gas 

Savings 

($/compressor)

Processing $75,000 $88,300 $46,109

Transmission/Storage $75,000 $88,300 0

The ICF International study (ICF, 2014) evaluated replacing a wet seal with a dry seal for 

centrifugal compressors (assuming 97% control of methane emissions) as a control option using 

their 2018 projected methane emission estimates (discussed in Section 3.8.2 of this document).

Their analysis assumed retrofit capital and annual operating costs of $400,000 and $17,500, 
39

respectively, and annual product revenue benefits of $180,500 (assuming $4/Mcf of gas) due to 

the reduction of product loss to the atmosphere. The report states that a dry seal retrofit is not 

common due to the high up-front costs and the downtime that would be required, and estimates 

that the payback period would be 29 months. The report also states that information from 

vendors indicates that 90% of new centrifugal compressors are already equipped with dry seals. 

4.4 Centrifugal Compressor - Wet Seal with a Flare

4.4.1 Description

Another emission reduction option for centrifugal compressors equipped with wet seals is 

to route the emissions to a combustion device or capture the emissions and route them to a fuel 

system. A wet seal system uses oil that is circulated under high pressure between three rings 

around the compressor shaft, forming a barrier against the compressed gas. The center ring is 

attached to the rotating shaft, while the two rings on each side are stationary in the seal housing, 

pressed against a thin film of oil flowing between the rings to both lubricate and act as a leak 

barrier. Compressed gas becomes absorbed and entrained in the fluid barrier and is removed 

using a heater, flash tank, or other degassing technique so that the oil can be recirculated back to 

the wet seal. The removed gas is either combusted, released to the atmosphere, or captured and 

routed to a process. The emission reduction technique investigated in this section is the use of 

wet seals with the removed gas sent to an enclosed flare.

4.4.2 Effectiveness

Flares have been used in the oil and gas industry to combust gas streams that have VOC

and methane constituents. A flare typically achieves 95% reduction of these compounds when 

operated according to the manufacturer instructions. For this analysis, it was assumed that 100%

of the entrained gas from the seal oil that is removed in the degassing process would be directed 

to a flare that achieves 95% reduction of organic compounds. The wet seal emissions in Table 3-

2 were used along with the control efficiency of the flare to calculate the emissions reductions 

from this option. A summary of the emission reductions is presented in Table 4-5.
40

Table 4-5. Estimated Annual Centrifugal Compressor Emission Reductions from 

Wet Seals Routed to a Flare

Oil & Gas Segment

Individual Compressor Emission Reductions 

(tons/compressor-year)

Methane VOC

Processing 216 19.5

Transmission/Storage 120 3.32

4.4.3 Cost of Controls

The capital and annual costs of the enclosed flare were calculated using the methodology 

in the EPA Control Cost Manual. (U.S. EPA, Cost) The heat content of the gas stream was 

calculated using information from an the EPA study to estimate the composition of natural gas 

previously developed for the analysis of subpart OOOO. (EC/R, 2011) A summary of the capital 

and annual operation and maintenance costs for wet seals routed to a flare is presented in Table 

4-6. There is no cost saving estimated for this option because the recovered gas is combusted.

Table 4-6. Costs for Centrifugal Compressor Wet Seals Routed to a Flare

Oil and Gas Segment Capital Cost ($2008) Annual Cost per Compressor

Processing $67,918 $98, 329

Transmission/Storage $67,918 $98,329

4.5 Centrifugal Compressor - Wet Seals with Gas Recovery for Use

4.5.1 Description

The final option for emissions reduction for wet seal centrifugal compressors is to capture 

and reroute the emissions back into the process. Based on comments received during 

development of subpart OOOO, in some cases gas may be routed back to the compressor suction 

or fuel system. 
41

4.5.2 Effectiveness

The emissions reductions for wet seal centrifugal compressors in the processing sector

and transmission and storage sectors are summarized in Table 4-7 using 95% control efficiency

for the capture system.

Table 4-7. Wet Seal Centrifugal Compressor Emission Reductions

at 95% Capture and Control

Source 

VOC

(tpy)

Methane

(tpy)

Emissions Reductions Per Wet Seal Centrifugal Compressor –

Natural Gas Processing 19.5 216

Emissions Reductions Per Wet Seal Centrifugal Compressor –

Transmission/Storage 3.32 120

4.5.3 Cost of Controls

Natural Gas STAR estimated the cost of a system of this type in which the seal oil 

degassing vents are routed to fuel gas or compressor suction to be $22,000 (U.S. EPA, 2009).

The estimated cost includes the installation of an intermediate pressure degassing drum, new 

piping, gas demister/filter, and a pressure regulator for the fuel line. The capital and installation 

costs were estimated using Guthrie’s modular method of equipment cost estimation (U.S. EPA, 

2009). The annual operating and maintenance cost of the systems was assumed to be minimal

(U.S. EPA, 2009). 

Because this option results in natural gas capture, savings can be realized from the use of 

the gas for beneficial purposes (e.g., the gas captured can replace other fuel that would have to 

be purchased). The per unit annual savings from natural gas is calculated by taking the value of 

the gas that is not emitted and routed to a useful purpose as a result of the capture control. This 

assumes that all gas that is not emitted is being routed for a useful purpose, which is reasonable 

given the available information on the destination of recovered seal oil degassing streams. Using 

the methane reductions provided in Table 4-7, the value of the natural gas saved is estimated to 

be $44,729 per year for centrifugal compressors equipped with one wet seal in the natural gas 
42

processing sector and $24,849 per year for centrifugal compressors equipped with one wet seal 

in the transmission/storage sector. These cost savings assume the value of the natural gas saved 

is $4/Mscf and the natural gas has a methane content of 92.8%. 

Natural Gas STAR estimated the potential cost benefit of installing a seal oil capture

system that uses the captured gas to fuel onsite boilers and heaters (U.S. EPA, 2009). The report 

estimates the potential gas savings from reduced site fuel gas consumption to be 63,000 Mscf/yr

(U.S. EPA, 2009). At $4/Mscf, the potential cost savings from reduced fuel consumption would 

be $252,000 per year, not including the capital cost of the seal oil gas capture system.

The ICF International study (ICF, 2014) calculated emission control cost curves ($/Mcf 

of methane reduced) using their 2018 projected methane emission estimates (discussed in 

Section 3.8.2 of this document). The report evaluated the cost of preventing emissions from the 

use of centrifugal compressors with wet seals by capturing the seal oil degassing stream from a 

small disengagement vessel and recycling it back into the compressor suction (or for us as high 

pressure turbine fuel or low pressure fuel gas to heaters) (assuming up to 99% control of methane 

emissions) using their 2018 projected methane emission estimates. Their analysis assumed 

capital costs of $33,700 (for seal oil gas separator, seal oil gas demister for low quality gas, and 

seal oil gas demister for high quality gas), minimal annual operating costs, and annual product 

revenue benefits per centrifugal compressor of $120,000 (assuming $4/Mcf of gas) due to the 

reduction of product loss to the atmosphere. The estimated payback period for this control option 

was estimated to be three months. In total, the study estimated that methane emissions would be 

reduced by 19.1 Bcf (397,567 tons) methane/yr nationally. The study also estimated that VOC 

emissions would be reduced by 72,800 MT (or approximately 80,226 tons) nationally at a cost of 

$806/ton of VOC reduced. 

5.0 SUMMARY

The EPA has used the data sources, analyses and studies discussed in this paper to form 

the Agency’s understanding of vented VOC and methane emissions from centrifugal and 

reciprocating compressors and the applicable emissions mitigation techniques. The following are 
43

characteristics the Agency believes are important to understanding this source of VOC and 

methane emissions:

 Reciprocating compressors may be found throughout the oil and natural gas sector. 

Centrifugal compressors are predominantly used in the processing and transmission 

segments.

 The net 2012 methane emissions reported for compressors for the 2014 GHG Inventory 

were 86,259 MT for the natural gas production segment, 724,295 MT for the natural gas

processing segment, and 1,261,080 MT for the natural gas transmission and storage 

segment, for a total of 2,071,633 MT of methane. 

 Reciprocating compressor emissions may be controlled by periodic replacement of rod 

packing systems. Additionally, new technologies are being used that capture these 

emissions and route them back to the process, both reducing emissions and providing an 

economic benefit.

 Centrifugal compressor emissions may be controlled by using dry seals in place of wet 

seals. Dry seal centrifugal compressors have lower emissions, require less maintenance, 

and are more energy efficient that wet seal centrifugal compressors and the cost of the 

two technologies is similar.

 When wet seal centrifugal compressors are used, it may be feasible to capture emissions 

from the seal oil and route the recovered gas back to the compressor or another process, 

or combust the gas. Routing the gas back to a process reduces the loss to the atmosphere 

and reduces the destruction of natural gas.

6.0 CHARGE QUESTIONS FOR REVIEWERS

1. Please comment on the national estimates of methane emissions and methane emission 

factors for vented compressor emissions presented in this paper. Please comment on the 

activity data and the methodologies used for calculating emission factors presented in this 

paper.
44

2. Did this paper appropriately characterize the different studies and data sources that quantify 

vented emissions from compressors in the oil and gas sector?

3. Did this paper capture the full range of technologies available to reduce vented emissions 

from reciprocating compressors and wet seal centrifugal compressors at oil and gas facilities? 

In particular, are there other options for reducing emissions at existing reciprocating or 

centrifugal compressors? For example, the EPA is aware of “low emissions packing” for 

reciprocating compressors but has no detailed information on this technology.

4. Did this paper appropriately characterize the emissions reductions achievable from the 

emissions mitigation technologies discussed for reciprocating compressors and wet seal 

centrifugal compressors?

5. Did this paper appropriately characterize the capital and operating costs for the technologies 

discussed for reduction of vented emissions from reciprocating compressors and wet seal 

centrifugal compressors? 

6. If there are emissions mitigation options for reciprocating and centrifugal compressors that 

were not discussed in this paper, please comment on the pros and cons of those options.

Please discuss the efficacy, cost and feasibly for both new and existing compressors.

7. Are there technical limitations that make the replacement of wet seals with dry seals 

impractical at certain existing centrifugal compressors?

8. Are there technical reasons why an operator would use a wet seal centrifugal compressor 

without a gas recovery system?

9. Are there technical limitations that make the installation of gas capture systems at certain 

reciprocating compressors impractical?

10. Please comment on the prevalence of the different emission mitigation options in the field.

11. Given the substantial benefits of dry seal systems (e.g., lower emissions, less maintenance, 

and higher efficiency), are you aware of situations where new wet seal centrifugal 

compressors are being installed in the field? If so, are there specific applications that require 

wet seal compressors?

12. Are there ongoing or planned studies that will substantially improve the current 

understanding of vented VOC and methane emissions from reciprocating and centrifugal 

compressors and available techniques for increased product recovery and emissions 

reductions?
45

7.0 REFERENCES

American Petroleum Institute (API) and America’s Natural Gas Alliance (ANGA). 2012. 

Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production. Summary 

and Analysis of API and ANGA Survey Responses. Final Report. September 21, 2012.

Clearstone Engineering, Ltd., 2006. Cost-Effective Directed Inspection and Maintenance Control 

Opportunities at Five Gas Processing Plants and Upstream Gathering Compressor Stations and 

Well Sites. 2006.

EC/R, Incorporated. 2011. Memorandum to Bruce Moore from Heather Brown. Composition of 

Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking. EC/R, Incorporated. June 

29, 2011. 

El Paso Corporation. 2010. Comments from El Paso Corporation on the Proposed Rule for 

Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems. Federal 

Register, Vol. 75, No. 69, Docket ID No.EPA-HQ-OAR-2009-0923.

Gas Research Institute (GRI)/U.S. Environmental Protection Agency. 1996a. National Risk 

Management Research Laboratory. GRI/EPA Research and Development, Methane Emissions 

from the Natural Gas Industry, Volume 8: Equipment Leaks. Prepared for the U.S. Department of 

Energy, Energy Information Administration. EPA-600/R-96-080h. June 1996.

Gas Research Institute (GRI)/U.S. Environmental Protection Agency. 1996b. Research and 

Development, Methane Emissions from the Natural Gas Industry, Volume 8: Equipment Leaks. 

June 1996. (EPA-600/R-96-080h).

REM Technology Inc. and Targa Resources. 2012. Reducing Methane and VOC Emissions. 

Presentation for the 2012 Natural Gas STAR Annual Implementation Workshop.

REM Technology Inc., et al. 2013. Profitable Use of Vented Emission in Oil & Gas Production. 

Prepared with support from the Climate Change and Emissions Management Corporation 

(CCEMC).

URS Corporation/University of Texas at Austin. 2011. Natural Gas Industry Methane Emission 

Factor Improvement Study, Final Report. December 2011. 

http://www.utexas.edu/research/ceer/GHG/files/FReports/XA_83376101_Final_Report.pdf.

U.S. Energy Information Administration (U.S. EIA). 2010. Annual U.S. Natural Gas Wellhead 

Price. Energy Information Administration. Natural Gas Navigator. Retrieved December 12, 

2010. Available at http://www.eia.doe.gov/dnav/ng/hist/n9190us3a.htm.

U.S. Energy Information Administration (U.S. EIA). 2012a. Total Energy Annual Energy 

Review. Table 6.4 Natural Gas Gross Withdrawals and Natural Gas Well Productivity, Selected 

Years, 1960-2011. http://www.eia.gov/totalenergy/data/annual/pdf/sec6_11.pdf.
46

U.S. Energy Information Administration (U.S. EIA). 2012b. Total Energy Annual Energy 

Review. Table 5.2 Crude Oil Production and Crude Oil Well Productivity, Selected Years, 1954-

2011. http://www.eia.gov/total energy/data/annual/pdf/sec5_9.pdf.

U.S. Energy Information Administration (U.S. EIA). 2013. Annual Energy Outlook 2013. 

Available at http://www.eia.gov/forecasts/aeo/pdf/0383%282013%29.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2006a. Lessons Learned: Reducing 

Methane Emissions from Compressor Rod Packing Systems. Natural Gas STAR. Environmental 

Protection Agency. 2006.

U.S. Environmental Protection Agency (U.S. EPA). 2006b. U.S. Environmental Protection 

Agency Lessons Learned Document. Replacing Wet Seals with Dry Seals in Centrifugal 

Compressors. October 2006. Available at http://epa.gov/gasstar/documents/ll_wetseals.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2009. Natural Gas STAR, Partner Update, 

Prospective Projects Spotlight – Potential New Opportunity: Seal Oil Degassing Vent Recovery 

and Use, Spring 2009. http://www.epa.gov/gasstar/documents/ngspartnerup_spring09.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2011a. Methodology for Estimating CH4 

and CO2 Emissions from Petroleum Systems. Greenhouse Gas Inventory: Emission and Sinks 

1990-2009. Washington, DC. April 2011. 

U.S. Environmental Protection Agency (U.S. EPA). 2011b. Oil and Natural Gas Sector: 

Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and 

Distribution. Background Technical Support Document for Proposed Standards, July 2011. 

EPA-453/R-11002.

U.S. Environmental Protection Agency (U.S. EPA). 2011c. Gas STAR PRO No. 104. Install 

Automated Air/Fuel Ratio Controls. 2011. Available at: http://epa.gov/gasstar/documents/autoair-fuel-ratio.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2011d. Gas STAR PRO No. 203. Pipe 

Glycol Dehydrator to Vapor Recovery Unit. 2011. Available at: 

http://epa.gov/gasstar/documents/pipeglycoldehydratortovru.pdf.

U.S. Environmental Protection Agency (U.S. EPA). 2012. Oil and Natural Gas Sector: 

Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and 

Distribution. Background Supplemental Technical Support Document for Proposed Standards, 

April 2012.

U.S. Environmental Protection Agency (U.S. EPA). 2013. Greenhouse Gas Reporting Program, 

Petroleum and Natural Gas Systems, Reporting Year 2012 Data. Data reported by facilities as of 

September 1, 2013. http://www.epa.gov/enviro/.

U.S. Environmental Protection Agency (U.S. EPA). 2014. Inventory of Greenhouse Gas 

Emissions and Sinks: 1990-2012. Washington, DC. April 2013.
47

(http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2014-

Chapter-3-Energy.pdf).

U.S. Environmental Protection Agency (U.S. EPA). EPA Air Pollution Control Cost Manual -

Sixth Edition, (EPA 452/B-02-001).

U.S. Environmental Protection Agency/ICF International. 2009. Methane’s Role in Promoting 

Sustainable Development in the Oil and Natural Gas Industry. U.S. EPA, ICF International, 

PEMEX, EnCana Oil & Gas, Hy-Bon Engineering, Pluspetrol, Gazprom, VNIIGAZ. World Gas 

Conference. October 2009. Available at: 

http://www.epa.gov/gasstar/documents/best_paper_award.pdf.